1. Field of the Invention
The present invention is related to rotary drilling of subterranean formations and, more specifically, to a rotary drill bit exhibiting particularly beneficial lateral stabilization characteristics, as well as a method of drilling subterranean formations with such a rotary drill bit.
2. State of the Art
Equipment used in subterranean drilling operations is well known in the art and generally comprises a rotary drill bit attached to a drill string, including drill pipe and drill collars. A rotary table or other device such as a top drive is used to rotate the drill string from a drilling rig, resulting in a corresponding rotation of the drill bit at the free end of the string. Fluid-driven downhole motors are also commonly employed, generally in combination with a rotatable drill string, but in some instances as the sole source of rotation for the bit. The drill string typically has an internal bore extending from and in fluid communication between the drilling rig at the surface and the exterior of the drill bit. The string has an outer diameter smaller than the diameter of the well bore being drilled, defining an annulus between the drill string and the wall of the well bore for return of drilling fluid and entrained formation cuttings to the surface.
An exemplary rotary drill bit includes a bit body secured to a steel shank having a threaded pin connection for attaching the bit body to the drill string, and a body or crown comprising that part of the bit fitted on its exterior with cutting structures for cutting into an earth formation. Generally, if the bit is a fixed-cutter or so-called xe2x80x9cdragxe2x80x9d bit, the cutting structure includes a plurality of cutting elements including cutting surfaces formed of a superabrasive material such as polycrystalline diamond and oriented on the bit face generally in the direction of bit rotation. A drag bit body is generally formed of machined steel or a matrix casting of hard particulate material such as tungsten carbide in a (usually) copper-based alloy binder.
In the case of steel body bits, the bit body is usually machined, typically using a computer-controlled, five-axis machine tool, from round stock to the desired shape, including internal watercourses and passages for delivery of drilling fluid to the bit face, as well as cutting element pockets or sockets and ridges, lands, nozzle displacements, junk slots and other external topographic features. Hardfacing is applied to the bit face and to other critical areas of the bit exterior, and cutting elements are secured to the bit face, generally by inserting the proximal ends of studs on which the cutting elements are mounted into apertures (sockets) bored into the bit face or, if cylindrical cutting elements are employed, by inserting the substrates into pockets bored into the bit face. The end of the bit body opposite the bit face is then threaded, made up and welded to the bit shank.
The body of a matrix-type drag bit is cast in a mold interiorly configured to define many of the topographic features on the bit exterior, with additional preforms placed in the mold defining the remainder of such features as well as internal features such as watercourses and passages. Tungsten carbide powder and sometimes other metals to enhance toughness and impact resistance are placed in the mold under a liquefiable binder in pellet form. The mold assembly, including a steel bit blank having one end inserted into the tungsten carbide powder, is placed in a furnace to liquify the binder and form the body matrix with the steel bit blank integrally secured to the body. The blank is subsequently affixed to the bit shank by welding. Superabrasive cutting elements, also termed xe2x80x9ccuttersxe2x80x9d herein, may be secured to the bit face during the furnacing operation if the elements are of the so-called xe2x80x9cthermally stablexe2x80x9d type, or may be brazed by their supporting (usually cemented WC) substrates to the bit face, or to WC preforms furnaced into the bit face during infiltration. Such superabrasive cutting elements include polycrystalline diamond compacts (PDCs), thermally stable polycrystalline diamond compacts (generally termed xe2x80x9cTSPsxe2x80x9d for thermally stable products), natural diamonds and, to a lesser extent, cubic boron nitride compacts.
Rotary drill bits, and more specifically drag bits, may be designed as so-called xe2x80x9canti-whirlxe2x80x9d bits. Such bits use an intentionally unbalanced and oriented lateral or radial force vector, usually generated by the bit""s cutters, to cause one side of the bit configured as an enlarged, cutter-devoid bearing area comprising one or more gage pads to ride continuously against the side wall of the well bore to prevent the inception of bit xe2x80x9cwhirlxe2x80x9d, a well-recognized phenomenon wherein the bit precesses around the well bore and against the side wall in a direction counter to the direction in which the bit is being rotated. Whirl can result at the least in an over-gage and out-of-round well bore and, at its worst, in damage to the cutters and bit itself. Anti-whirl bits have been designed, built and run commercially, with some success. However, the necessity to calculate, and usually redirect, the lateral imbalance forces generated by engagement of a formation by a bit under rotation and weight on bit (WOB) so that the resultant lateral force vector intersects the bearing area results in additional expense in the first instance of completing a given bit design. Further, if the size, shape, type, orientation or location of any cutting element is desired or required to be changed, the magnitude and direction of the resultant lateral force vector must be recalculated, and possibly further design modifications effected to the bit to ensure proper direction and magnitude of the resultant lateral force vector.
Another disadvantage of anti-whirl bits is related to the absence of cutting elements on the shoulder as well as the gage in the bearing area, often in conjunction with longitudinally extending the gage pad or pads. While bits of such designs exhibit a high side force directed to the relatively low-friction gage pad or pads in the bearing area, resulting in reduced vibration and a smooth-running bit, the absence of the gage and shoulder cutting elements in the bearing area significantly reduces the life of the bit through premature wear.
Thus, it would be beneficial to the drill bit design to achieve a smooth-running, low-vibration drill bit which does not require the intricacies of anti-whirl bit design and re-design and which, at the same time, provides a useful life on the order of that obtainable by a conventional, nonanti-whirl drill bit.
The present invention provides a fixed cutter, or rotary drag, bit exhibiting enhanced lateral stability and reduced vibrational tendencies comparable to an anti-whirl bit, while at the same time providing a greater useful life in terms of resistance to wear.
The rotary drag bit of the present invention includes a bit body having a face over which may extend a plurality of generally radially extending blades, each bearing a plurality of superabrasive cutting elements. The bit body also includes a plurality of gage pads, which may comprise longitudinal extensions of the blades, or be discontinuous therewith. At least one gage pad of the plurality exhibits a longitudinal elongation toward, or even longitudinally below, the face of the bit which moves the shoulder region comprising a transition between the gage and the face profiles downwardly, as the bit is normally oriented for drilling. At least one cutting element is placed in the area of gage pad elongation, the at least one cutting element exhibiting an exposure less than the exposure of cutting elements on the bit face. Desirably, at least another reduced-exposure cutting element is placed in the shoulder region forming the transition between the gage pad and its associated blade.
The rotary drag bit of the present invention may be configured as a conventional or anti-whirl bit in terms of the degree and magnitude of the resultant lateral force vector causing lateral imbalance of the bit. However, a bit in accordance with the present invention may also employ all of the gage pads in the above-described longitudinally elongated configuration, each of the gage pads bearing at least one cutting element of lesser exposure than the bit face cutting elements and at least another cutting element of lesser exposure on the shoulder region. By using such an approach, the direction of lateral bit imbalance is of little or no concern to the bit designer, who need only determine that the magnitude of such imbalance is within certain broad parameters. Further, the magnitude of the lateral bit imbalance may be increased beyond that deemed wise conventionally, so as to more firmly stabilize the rotating bit against the side wall of the borehole, the extended gage region and reduced-exposure cutting elements providing sufficient durability and wear resistance to accommodate the increased lateral loading.
Thus, a bit in accordance with the present invention may be of conventional design and exhibit a wide variation in lateral imbalance, from a very low magnitude to a magnitude in excess of what have hitherto been deemed to be acceptable levels, or may be of an anti-whirl design. In addition, the term xe2x80x9crotary drill bitxe2x80x9d or xe2x80x9cbitxe2x80x9d as employed herein encompasses core bits, bi-center bits, eccentric bits, reaming-while-drilling (RWD) tools, as well as other rotary drilling structures which may benefit from the improvements and advantages afforded by the present invention.
The present invention also encompasses a method of drilling subterranean formations.